Only a portion of the oil originally present in a subterranean oil-bearing formation is recovered during the primary production cycle. During primary production only the natural pressure present in the formation is exploited for oil recovery. Waterflooding is the most commonly used secondary recovery process. Injection of water into strategically located wells serves to revive formation pressure and to physically displace oil present in the subterranean formation. However, large volumes of the original in-place hydrocarbons, in some instances as high as 50%, still remain trapped in the reservoir even after waterflooding.
Numerous approaches have been taken to try and recover the residual oil after waterflooding has ceased to be economical. These have included thermal methods, such as steam stimulation, fire flooding and in situ combustion. Recovery processes have also utilized components such as nitrogen, carbon dioxide and light hydrocarbon gases to displace residual oil. For formations containing lighter oil deposits, for example, oil-bearing strata where the API gravity of the oil phase is 10 or greater, the dominant method for enhanced oil recovery has been carbon dioxide injection. In some limited instances where the oil producing strata are at substantially greater depths, nitrogen has been used because greater injection pressures are required. In some locations, particularly parts of Alaska and Canada, light hydrocarbon gases which are generated during the oil recovery step are subsequently reinjected for pressure maintenance and for the recovery of additional oil.
In a miscible flooding operation, the injected solvent is capable of forming a single phase solution with the oil in place, which assists in the oil recovery step. Barring any areal sweep inefficiencies, a miscible drive process can effectively displace oil from the parts of the reservoir through which the solvent flows because a single phase is flowing through the formation. In multiple phase flow, interfaces and the retentive forces of capillarity and interfacial tension have to be overcome before the oil can be displaced.
Carbon dioxide is the most commonly used solvent in light gas displacement processes. Under certain appropriate conditions of oil gravity and reservoir temperature and pressure, carbon dioxide is first contact miscible with reservoir hydrocarbons. However, if the reservoir temperature is too high, or the reservoir pressure is not high enough, carbon dioxide may not be first contact miscible with the in-place hydrocarbons. In such instances, multiple contact miscibility between the injected carbon dioxide and the in-place hydrocarbons is still possible. During multiple contact miscibility, the neat carbon dioxide initially injected continues to strip light hydrocarbons from successive contacts with the in-place hydrocarbons, until it achieves a composition suitable for miscibility with the in-place fluids.
When carbon dioxide first contacts reservoir hydrocarbons, it dissolves in the oil phase, thus swelling the hydrocarbon fluids and reducing their viscosity. Both of these effects have a very positive influence on final oil production. By swelling the oil, an expansion of the oil phase into existing flowing channels facilitates additional oil recovery. By lowering oil viscosity, the energy required to move the oil through the pore structures in the reservoir is minimized, and again more oil is accessed by the displacing solvent. These two positive effects attend the injection of carbon dioxide irrespective of the displacement process that results.
Both nitrogen and light hydrocarbons will show similar positive effects when injected into oil bearing formation. Nitrogen, however, is less soluble in the oil phase. Therefore, oil swelling and viscosity reduction of the in-place hydrocarbons is not as pronounced. Additionally, much higher pressures (relative to carbon dioxide) are required for nitrogen to achieve first or multiple contact miscibility with crude oils.
Light hydrocarbons are excellent displacing solvents for oil because they are readily soluble causing high swelling and viscosity reduction, and readily achieve first or multiple contact miscibility with the in-place oil phase. However, the expense of procuring these light hydrocarbons and the inefficiency in leaving large volumes of these hydrocarbons behind in the reservoir during the displacement process precludes the extensive use of such systems, except in remote locations where no market for the hydrocarbons is available.
Unfortunately, the efficacy of all these displacement processes is severely hampered by the low viscosity of the solvent phase at reservoir conditions. Thus, at typical reservoir conditions, e.g., 95.degree. F. and 3500 psia, the light gas displacement solvent can be expected to have a viscosity of less than 0.1 centipoise (cp), whereas most reservoir fluids range in value from 0.4 cp to 8 cp. Under these conditions, a very adverse mobility ratio between displaced and displacing fluids is created, resulting in fingering of the displacing fluid through the in-place reservoir fluids and early breakthrough of the injected solvent. This viscosity disparity tends to become even more pronounced at higher temperatures.
Because of the advantages that these light gas displacement processes offer, substantial effort has been expended to address the issue of low viscosity and early solvent breakthrough. One approach is to thicken the displacing solvent by dissolving a polymer phase in it for viscosity enhancement. However, the solvent property of nitrogen at reservoir conditions is too low to adequately dissolve anything other than low molecular weight components. Viscosity enhancement due to the dissolution of even large amounts of these low molecular weight components would be too insignificant to represent a meaningful improvement over the initial solvent viscosity.
Dissolution of polymers into light hydrocarbons is easier, and some results are available on the solubility of some polymer types in fluids like ethane, ethylene, propane, propylene, butane, and butylene. For example, U.S. Pat. No. 3,354,953 issued to Morris teaches the use of crude oil miscible solvents such as propane to displace crude oil through a formation. Morse further suggests that the viscosity of the propane can be controlled by the addition of kerosene. In U.S. Pat. No. 3,570,601 issued to Dauben et al teaches the recovery of oil using viscous propane, where the propane viscosity is increased by the dissolution of a solid polymer such as polyisobutylene in a heavier hydrocarbon such as heptane, and then diluting this solution with the propane to form the oil driving bank.
An article entitled "CO.sub.2 as Solvent for Oil Recovery" by F. M. Orr, Jr. et al (Chemtech, August 1983, page 42, et seq.), discusses attempts to dissolve polymers into carbon dioxide. It was reported that low-molecular weight polymers dissolved in carbon dioxide resulted in only a 10% to 20% increase in solution viscosity.
A later study on polymer solubility by J. P. Heller and J. J. Taber has been reported in "Development of Mobility Control Methods to Improve Oil Recovery by CO.sub.2 : Final Report," DOE/MC/10689-17. This study lists some 53 commercially available polymers which were tried in an effort to thicken the carbon dioxide, but with little success. U.S. Pat. No. 4,609,043 issued to Cullick teaches that the solubility of polymers in carbon dioxide can be enhanced by the addition of an entrainer, preferably a polar organic compound such as an alcohol or a glycol, to the carbon dioxide.
The prior art also discusses numerous indirect approaches that have been attempted for mobility control during miscible gas drives. Two prominent methods are WAG and foams. WAG, which stands for Water Alternating Gas, was developed in the late 1950's as an attempt to control the mobility of LPG (Liquid Petroleum Gas) floods. Theoretically, by alternating the injection of slugs of water and the displacing solvent, the relative permeability of the solvent phase can be lowered, and thus its mobility improved. However, because the WAG process requires an injection of large volumes of water, the solvent is blocked by this water phase from contacting in-place hydrocarbons. Additionally, gravitational effects away from the injection well will cause a segregation of the water phase and the lighter solvent. This gravity override of the solvent results in loss of mobility control.
A report entitled "Mobility Control for CO.sub.2 Floods--A Literature Survey" by J. P. Heller (DOE/MC/10689-3) outlines the historical basis for the development of the WAG process. This same literature survey also covers the development of foams for mobility control during miscible, light gas drives. Another report which offers a historical treatment of the use of foam technology is entitled "Foams in Porous Media"--SUPRI TR-49 by S. S. Marsden (DOE/SF/11564-15).
U.S. Pat. No. 2,866,507, "Gas Drive Recovery Process" issued to D. C. Bond and O. C. Holbrook, suggested the injection of an aqueous slug containing water-soluble, foam-producing surfactants, followed by gas injection for the formation of foam. Since then, many studies have been directed at understanding the nature and flow of these foams in reservoirs, and toward successfully implementing these foams in the oil field.
Based on these laboratory studies, two factors of primary importance with regard to the use of foams were established. First, gas phase mobilities could be substantially reduced in laboratory core experiments by either simultaneous or sequential injection of a gas and an aqueous surfactant solution. Second, for some surfactant systems, the presence of an oil phase was detrimental to foam formation, which effect could be mitigated by increasing the surfactant concentration.
In order to form a foam, three ingredients are required. A continuous aqueous phase, a water soluble surfactant to lower the interfacial tension, and a dispersed gas phase, such as air or nitrogen, or pseudo-gas or fluid phase such as supercritical carbon dioxide. Some drive mechanism that will move the dispersed phase through the continuous aqueous phase is also necessary to form the lamella structures which comprise a foam. In the absence of these three ingredients and a driving mechanism, foam will not form.
Thus, the formation and propagation of foams through porous media is dictated largely by the availability of the gas and aqueous surfactant phases. The reason foams have not been more successfully exploited in actual field applications is because the movement and availability of the three required components cannot be controlled with any certainty. For example, in a publication entitled "The Mechanism of Gas and Liquid Flow Through Porous Media in the Presence of Foam," published in SPEJ, 8, 1968, pages 359 to 369, L. W. Holm measured the frontal velocity of tracer concentrations in both gas and liquid phases of a moving foam. In general, different frontal velocities were measured for the liquid and gas components of the foam.
The lower density and much lower viscosity of the gas phase relative to the liquid phase, will result in the gas phase having a much higher mobility relative to the liquid phase. Therefore, the gas phase will always be moving faster than the liquid phase. As a consequence, the injected aqueous phase containing the surfactant will not be available to the gas phase for foam generation and mobility control once the gas breaks through the foam front.
This disadvantage limits the usefulness of foam as a mobility control mechanism, regardless of whether the gas and surfactant are simultaneously injected into the formation or the foam is pre-formed prior to injection. SPE/DOE Paper 14962 entitled "Slim-Tube Investigation of CO.sub.2 Foams," which was presented at the Fifth SPE/DOE Symposium on Enhanced Oil Recovery held in Tulsa, Okla., Apr. 20-23, 1986, confirmed this shortcoming and disclosed injecting all the surfactant solution into the formation and then chasing it with carbon dioxide. This approach yielded a foam front that steadily advanced through the formation. While it solved some of the problems associated with mobility control, it did not ensure that the surfactant was adequately contacted by the carbon dioxide during the operation.